Field of the Invention
This invention relates generally to the field of exploration and production for hydrocarbons. More specifically, the invention relates to a method of pore type classification for petrophysical rock typing.
Background of the Invention
To optimize the production of hydrocarbon reserves from a subsurface formation or reservoir, petroleum engineers seek to understand the physical properties of these formations, including their porosity and permeability. For many geologic formations, their physical properties are determined primarily as they are deposited, and modified to some extent by pressure and heat. Therefore it is possible to describe and classify such geologic formations in terms of their depositional environments, with some acknowledgement of subsequent changes to the physical properties. By way of background, rock typing is a process of classifying reservoir rocks into distinct units, each of which was deposited under similar geological conditions and may have undergone similar diagenetic alterations. A given rock type, when accurately classified, is characterized by a unique permeability/porosity relationship, capillary pressure profile (or J function), and set of relative permeability curves. As a result, rock typing can lead to the estimation of formation permeability; and subsequently, the consistent and realistic simulation of reservoir dynamic behavior and production performance. In other words, proper rock typing may be used to accurately predict future or potential reservoir production through reservoir simulation methods, and may be used to make decisions as to where in a formation to drill certain wells or develop an existing hydrocarbon producing formation.
Much of the known reserves of oil and gas around the world are found in formations with complex pore systems (carbonates or unconventional reservoirs). This complexity is due to a combination of complex depositional rock fabric textures and diagenetic modification of the rocks. Post-depositional processes can modify the original petrophysical properties (e.g. permeability and irreducible water saturation) and result in a disconnection between original depositional rock fabric and current reservoir properties. However, a method has not yet been developed to describe the dominant pore type groups (PTGs) occurring within such a reservoir, and their associated petrophysical properties. These PTGs are determined independently of geological facies.
The shape of the mercury injection capillary pressure (MICP) curve reflects characteristics of a rock's porosity network, such as the distribution of pore and pore throat sizes, interconnectivity of the pores, and sorting of the pore throat sizes. Realizing that rocks of differing pore systems yield differently shaped capillary pressure curves, then representing the capillary pressure curve with a set of parameters that embodies these differences provides a means to easily group, or classify rocks according to unique combinations of these model parameters. Because the pore network governs the movement of fluids, the model can be used for saturation height analysis and permeability prediction.
Consequently, there is a need for methods and systems for pore type classification in petrophysical rock typing.